The present invention relates generally to a downhole telemetry system for facilitating the measurement of borehole and drilling data, storing the data in memory, and transmitting the data to the surface for inspection and analysis. More particularly, the invention relates to a measurement-while-drilling ("MWD") system that senses and transmits data measurements from the bottom of a downhole assembly a short distance around components in the drill string. Still more particularly, the present invention relates to an MWD system capable of measuring environmental conditions and operating parameters relating to the drill bit and/or motor and transmitting the data measurements real-time around the motor.
The advantages of obtaining downhole data measurements from the motor and drill bit during drilling operations are readily apparent to one skilled in the art. The ability to obtain data measurements while drilling, particularly those relating to the operation of the drill bit and motor and the environmental conditions in the region of the drill bit, permit more economical and more efficient drilling. Some of the primary advantages are that the use of real time transmission of bit temperatures permits real time adjustments in drilling parameters for optimizing bit performance, as well as maximizing bit life. Similar measurements of drilling shock and vibration allow for adjusting or "tuning" parameters to drill along the most desirable path, or at the "sweet spot," thereby optimizing and extending the life of the drilling components. Measurement of the inclination angle in the vicinity of the drill bit enhances drilling control during directional drilling.
One advantage of positioning sensors closer to the bit is made clear in the following example, shown in FIG. 1. FIG. 1 depicts a downhole formation, with an oil-producing zone that has a depth of approximately twenty-five feet. A conventional steerable drilling assembly is shown in FIG. 1, which includes a drill bit, a motor, and a sensor sub located between 25-50 feet above the drill bit. As shown in FIG. 1, the drill bit and motor have passed substantially through the oil-producing zone before the sensors are close enough to detect the zone. As a result, time is wasted in re-positioning and re-directing the downhole assembly. This is particularly costly in a situation where the intended well plan is to use the steerable system in FIG. 1 to drill horizontally in the zone.
If the sensors were located in or closer to the bit, the sensors would have detected the zone sooner, and the direction of the drilling assembly in FIG. 1 could have been altered sooner to drill in a more horizontal direction to stay in the oil-producing zone.
This, of course, is but one example of the advantages of placing the sensors in or very near to the bit. Other advantages of recovering data relating to the drill bit and motor will be apparent to those skilled in the art.
There are a number of systems in the prior art which seek to transmit information regarding parameters downhole up to the surface. None of these prior art telemetry systems, however, senses and transmits data regarding operational, environmental, and directional parameters from below a motor to a position above the motor. These prior systems may be descriptively characterized as: (1) mud pressure pulse; (2) hard-wire connection; (3) acoustic wave; and (4) electromagnetic waves.
In a mud pressure pulse system, the drilling mud pressure in the drill string is modulated by means of a valve and control mechanism mounted in a special pulser collar above the drill bit and motor (if one is used). The pressure pulse travels up the mud column at or near the velocity of sound in the mud, which is approximately 4000-5000 feet per second. The rate of transmission of data, however, is relatively slow due to pulse spreading, modulation rate limitations, and other disruptive forces, such as the ambient noise in the drill string. A typical pulse rate is on the order of a pulse per second. A representative example of mud pulse telemetry systems may be found in U.S. Pat. Nos. 3,949,354, 3,964,556, 3,958,217, 4,216,536, 4,401,134, 4,515,225, 4,787,093 and 4,908,804.
Hard-wire connectors have also been proposed to provide a hard wire connection from the bit to the surface. There are a number of obvious advantages to using wire or cable systems, such as the ability to transmit at a high data rate; the ability to send power downhole; and the capability of two-way communication. Examples of hard wire systems may be found in U.S. Pat. Nos. 3,879,097, 3,918,537 and 4,215,426.
The transmission of acoustic or seismic signals through a drill pipe or the earth (as opposed to the drilling mud) offers another possibility for communication. In such a system, an acoustic or seismic generator is located downhole near or in the drill collar. A large amount of power is required downhole to generate a signal with sufficient intensity to be detected at the surface. The only way to provide sufficient power downhole (other than running a hard wire connection downhole) is to provide a large power supply downhole. An example of an acoustic telemetering system is Cameron Iron Works' CAMSMART downhole measurement system, as published in the Houston Chronicle on May 7, 1990, page 3B.
The last major prior art technique involves the transmission of electromagnetic ("EM") waves through a drill pipe and the earth. In this type of system, downhole data is input to an antenna positioned downhole in a drill collar. Typically, a large pickup assembly or loop antenna is located around the drilling rig, at the surface, to receive the EM signal transmitted by the downhole antenna.
The major problem with the prior art EM systems is that a large amount of power is necessary to transmit a signal that can be detected at the surface. Propagation of EM waves is characterized by an increase in attenuation with an increase in distance, data rate and earth conductivity. The distance between the downhole antenna and the surface antenna may be in the range of 5,000 to 10,000 feet. As a result, a large amount of attenuation occurs in the EM signal, thereby necessitating a more powerful EM wave. The conductivity of the earth and the drilling mud also may vary significantly along the length of the drill string, causing distortion and/or attenuation of the EM signal. In addition, the large amount of noise in the drilling string causes interference with the EM wave.
The primary way to supply the requisite amount of power necessary to transmit the EM wave to the surface is to provide a large power supply downhole or to run a hard wire conductor downhole. Representative examples of EM systems can be found in U.S. Pat. Nos. 2,354,887, 3,967,201, 4,215,426, 4,302,757, 4,348,672, 4,387,372, 4,684,946, 4,691,203, 4,710,708, 4,725,837, 4,739,325, 4,766,442, 4,800,385, and 4,839,644.
There have been attempts made in the prior art to reduce the effects of attenuation which occur during the transmission of an EM signal from down near the downhole drilling assembly to the surface. U.S. Pat. No. 4,087,781, issued to Grossi, et al., for example, discloses the use of repeater stations to relay low frequency signals to and from sensors near the drilling assembly. Similarly, U.S. Pat. No. 3,793,632 uses repeater stations to increase data rate and, in addition, suggests using two different modes of communication to prevent interference. U.S. Pat. Nos. 2,411,696 and 3,079,549 also suggest using repeater stations to convey information from downhole to the surface. None of these systems has been successful, based primarily on the varying conditions encountered downhole, where conductivity may range over several orders of magnitude.
Moreover, none of the prior art systems has addressed the additional problems which arise when the telemetry system is located below a motor or turbine. A motor causes additional problems because, by definition, one end of the motor has a relative motion with respect to the other end. This motion hinders the transmission of signals by any of the known techniques. Moreover, the fact that the motor has a relative motion at one end with respect to the other also means that a large amount of noise is generated in the region of the motor, thereby making it more difficult to communicate signals in the vicinity of the motor.
Nor do the prior art references address the problems inherent in positioning the sensors in or very close to the drill bit, or recovering data from these sensors. The prior art systems place the sensors a distance above the drill bit to determine conditions above the drill bit.
Furthermore, space below the motor is extremely limited, so that there is not sufficient space for a power source to generate signals with the necessary intensity to reach the surface. This is especially true in a steerable system which has a bent housing, as shown in FIG. 2B. If the length of the assembly below the bent housing becomes too long, the side forces on the drill bit become excessive for the moment arm between the bent housing and the drill bit. Furthermore, when the motor is operating and the drill string is rotating, i.e., the system is drilling in a straight mode, the length between the drill bit and the bent housing becomes critical. The longer this length, the larger will be the diameter of the hole that will be drilled.
Thus, while it would be advantageous to obtain information regarding the operating parameters and environmental conditions of the drill bit and motor, to date no one has successfully developed a telemetry system capable of obtaining this data and transmitting it back to the surface.